Laboratory Evaluation of Formation Damage
Development of meaningful laboratory testing and data interpretation techniques for assessment of the formation damage potential of petroleum-bearing formations under actual scenarios of field operations, and for evaluation of techniques for restoration and stimulation of damaged formations are essential for efficient exploitation of petroleum reservoirs. Experimental systems and procedures should be designed to extract meaningful and accurate experimental data. The data should be suitable for use with the available analytical interpretation methods. This is important to develop reliable empirical correlations, verify mathematical models, identify the governing mechanisms, and determine the relevant parameters. These are then used to develop optimal strategies to mitigate the adverse processes leading to formation damage during reservoir exploitation. As expressed by Thomas et al. (1998):
Laboratory testing is a critical component of the diagnostic procedure followed to characterize the damage. To properly characterize the formation damage, a complete history of the well is necessary. Every phase, from drilling to production and injection, must be evaluated. Sources of damage include drilling, cementing, perforating, completion and workover, gravel packing, production, stimulation, and injection operations. A knowledge of each source is essential. For example, oil-based drilling mud may cause emulsion or wettability changes, and cementing may result in scale formation in the immediate wellbore area from pH changes. Drilling damage in horizontal wells can be very high because of the long exposure time during drilling (mud damage and the mechanical action of the drill pipe on the formation face); thus, the well's history may indicate several potential sources and types of damage.
For meaningful formation damage characterization, laboratory core flow tests should be conducted under certain conditions (Porter, 1989; Mungan, 1989):
1. Samples of actual fluids and formation rocks and all potential rockfluid interactions should be considered.
2. Laboratory tests should be designed in view of the conditions of all field operations, including drilling, completion, stimulation, and present and future oil and gas recovery strategies and techniques.
3. The ionic compositions of the brines used in laboratory tests should be the same as the formation brines and injection brines involving the field operations.
4. Cores from oil reservoir should be unextracted to preserve their native residual oil states.
This is important because Mungan (1989) says that "Crude oils, especially heavy and asphaltenic crudes, provide a built-in stabilizing effect for clays and fines in the reservoir, an effect that would be removed by extraction."
Fundamental Processes of Formation Damage in Petroleum Reservoirs
Formation damage in petroleum-bearing formation occurs by various mechanisms and/or processes, depending on the nature of the rock and fluids involved, and the in-situ conditions. The commonly occurring processes involving rock-fluid and fluid-fluid interactions and their affects on formation damage by various mechanisms have been reviewed by numerous studies, including Mungan (1989), Gruesbeck and Collins (1982), Khilar and Fogler (1983), Sharma and Yortsos (1987), Civan (1992, 1994, 1996), Wojtanowicz et al. (1987, 1988), Masikewich and Bennion (1999), and Doane et al. (1999). The fundamental processes causing formation damage can be classified as following:
Laboratory tests are designed to determine, understand and quantify the governing processes, their parameters, and dependency on the insitu and various operational conditions, and their effect on formation damage. Laboratory tests help determine the relative contributions of various mechanisms to formation damage. For convenience, the frequently encountered formation damage mechanisms can be classified into two groups (Amaefule et al., 1988; Masikewich and Bennion, 1999):
1 fluidfluid interactions and
2 fluid-rock interactions. The fluid-fluid interactions include:
a emulsion blocking,
b inorganic deposition, and
c organic deposition.
The fluid-rock interactions include:
a mobilization, migration and deposition of in-situ fine particles,
b invasion, migration and deposition of externally introduced fine particles,
c alteration of particle and porous media properties by surface processes such as absorption, adsorption, wettability change, swelling, and
d damage by other processes, such as counter-current imbibition, grinding and mashing of solids, and surface glazing that might occur during drilling of wells (Bennion and Thomas, 1994).
Selection of Reservoir Compatible Fluids
Masikewich and Bennion (1999) outlines the typical information, tests and processes necessary for laboratory testing and optimal design, and selection of fluids for reservoir compatibility. Hence, Masikewich and Bennion (1999) classify the effort necessary for fluid testing and design into six steps:
1. Identification of the fluid and rock characteristics
2. Speculation of the potential formation damage mechanisms
3. Verification and quantification of the pertinent formation damage mechanisms by various tests
4. Investigation of the potential formation damage mitigation techniques
5. Development of the effective bridging systems to minimize and/or avoid fluids and fines invasion into porous media
6. Testing of candidate fluids for optimal selection
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